Hydrocarbon production by fluidically isolating vertical regions of formations

ABSTRACT

Techniques of hydrocarbon production by fluidically isolating vertical regions of formation are described. A subterranean zone entrapping hydrocarbons includes multiple vertically arranged regions. Each region has a respective permeability for fluid flow. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the multiple vertically arranged regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.

TECHNICAL FIELD

This specification relates to a hydrocarbon production from a hydrocarbon reservoir.

BACKGROUND

Production wells are formed in hydrocarbon reservoirs to retrieve hydrocarbons. In some instances, injection wells are also formed in the same reservoir to enhance hydrocarbon production through the production wells. Sometimes, the factors within the reservoir, such as variable permeability, can cause injection fluid to flow from the injection wells into one region of the hydrocarbon reservoir more than another.

SUMMARY

This specification describes technologies relating to hydrocarbon production by fluidically isolating vertical regions of formations.

Certain aspects of the subject matter described here can be implemented as a method. A subterranean zone entrapping hydrocarbons includes multiple vertically arranged regions. Each region has a respective permeability for fluid flow. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the multiple vertically arranged regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.

This, and other aspects, can include one or more of the following features. The multiple vertically arranged regions can include a first region, a second region, and a third region vertically arranged in that sequence. A permeability of the first region can be more than a permeability of the second region and less than a permeability of the third region. To fluidically isolate the vertically arranged regions from each other, an injection tubing can be lowered into the injection well. The injection tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A first packer can be installed around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region. The first packer can have at least a thickness of the second region. To control the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region, a first valve can be installed in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region. The flow of the injection fluid into the first region and the third region can be controlled by controlling the first valve and the third valve, respectively. A first sensor can be installed in the portion of the injection tubing residing in the first region. The first sensor can be configured to sense a fluid parameter of the injection fluid flowed through the portion of the injection tubing. The flow of the injection fluid into the first region can be controlled based on the fluid parameter sensed using the first sensor. The first sensor can include a pressure sensor or a flow meter. A production tubing can be lowered into the production well. The production tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A second packer can be installed around the production tubing in an annulus between the production well and the subterranean zone and at a location of the second region. The second packer can have at least a thickness of the second region. A second sensor can be installed in the portion of the injection tubing residing in the first region. The second sensor can be configured to sense a temperature of the injection fluid flowed through the injection tubing. The flow of the injection fluid through the first region can be controlled based on the temperature sensed using the second sensor. The second sensor can include a pressure sensor or a flow meter. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining breakthrough of injection fluid from the injection well into the production well. To control the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well, breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides can be detected. The production well can be shut in at the surface. Injection fluid flow into the region of the subterranean zone in which the injection well resides can be shut off. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region. To control the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region, injection fluid flow can be shut off in response to determining the cross flow from the high permeability region to the low permeability region.

Certain aspects of the subject matter described here can be implemented as a method. A production well is formed in a subterranean zone that includes multiple vertically arranged regions. Each vertically arranged region has a respective permeability for fluid flow. The production well extends through the multiple regions. An injection well is formed in the subterranean zone to aid hydrocarbon production through the production well. The injection well extends through the multiple regions. At each of the production well and the injection well, the vertically arranged regions are fluidically isolated from each other. Injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.

This, and other aspects, can include one or more of the following features. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining breakthrough of injection fluid from the injection well into the production well. To control the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well, breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides can be detected. The production well can be shut in at the surface. Injection fluid flow into the region of the subterranean zone in which the injection well resides can be shut off. The flow of the injection fluid into each fluidically isolated region can be controlled based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region. To control the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region, injection fluid flow into the high permeability region can be shut off in response to determining the cross flow from the high permeability region to the low permeability region.

Certain aspects of the subject matter described here can be implemented as a method. A subterranean zone entrapping hydrocarbons includes a first region, a second region, and a third region vertically arranged in that sequence. A permeability of the first region is more than a permeability of the second region and less than a permeability of the third region. An open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production are formed in the subterranean zone through the three regions. At each of the production well and the injection well, the first region is fluidically isolated from the third region. Injection fluid injected through the injection well into the first region is substantially confined to flow in the first region and not the third region, and vice versa. A flow of the injection fluid into each fluidically isolated region is controlled to control a recovery of hydrocarbons trapped in each fluidically isolated region.

This, and other aspects, can include one or more of the following features. To fluidically isolate the first region from the third region, an injection tubing can be lowered into the injection well. The injection tubing can extend from a surface of the subterranean zone through the first region, the second region and the third region. A first packer can be installed around the injection tubing in an annulus between the injection well and the subterranean zone, and at a location of the second region. The first packer has at least a thickness of the second region. To control the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region, a first valve can be installed in a portion of the injection tubing residing in the first region and a second valve can be installed in a portion of the injection tubing residing in the third region. The flow of the injection fluid into the first region and the third region can be controlled by the first valve and the third valve, respectively.

The details of one or more implementations of the subject matter described in this specification are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of an example production field with fluidically isolated regions in the same reservoir zone.

FIG. 2 is a schematic of an example production field with open hole completions.

FIG. 3 is a schematic of the example production field of FIG. 1 with an isolated region.

FIG. 4 is a schematic of the example production field of FIG. 1 with isolated injection sections.

FIG. 5 shows a flowchart of an example method for creating and utilizing a production field with fluidically isolated regions in the same reservoir zone.

Like reference numbers and designations in the various drawings indicate like elements.

DETAILED DESCRIPTION

This disclosure describes a method for producing a hydrocarbon field which utilizes both injection and production wellbores. In hydrocarbon production, there are many methods that can be utilized to complete a wellbore including open hole completions. An open hole wellbore has no casing and leaves the rock of a geological formation exposed to the interior of the wellbore. Often in a production field, there are both production wellbores and injection wellbores. Hydrocarbons are produced out of production wellbores while fluid (for example, gas, water, brine, or other fluid) is injected into the formation with injection wellbores. The injection process helps “push” hydrocarbons towards the production wellbore where they can be produced. In the case of open hole completions, it is difficult to direct the injection fluid where it is needed. The injection fluid will follow the path of least resistance, that is, go through sections of the reservoir with higher permeability. The higher permeability areas of a reservoir typically need less injection fluid to push the hydrocarbons towards the production wells. This can result in early water breakthrough when the injection fluid starts being produced with the hydrocarbons. Alternatively, hydrocarbons are left in place within low to medium permeability regions of a production field. On top of hydrocarbons being left in place, injection fluids can cross flow from one porous region to another within the production wellbore and push hydrocarbons away from the production wellbore.

Early water breakthrough can occur when injection fluid has pushed much of the recoverable hydrocarbons out of its region leaving injection fluid free to be produced. Early water breakthrough can increase the water-cut, that is, the percentage of the production fluid that is water, of the production well. Higher water-cuts can lead to process and flow assurance issues, such as hydrate formation. Another potential issue is cross flow in the production wellbore. Cross flow occurs when there is sufficient pressure differential between two production regions to cause fluid flow in between them via the wellbore. This often occurs when the production wellbore is shut-in (not producing). When cross flow occurs, injection fluid can push hydrocarbons away from the production wellbore.

As described later, an integrated recovery system including production tubing, well-placed open hole packers, isolation valves, and various sensors, can prevent early water breakthrough and cross flow. The system described here also allows for targeted injection and production within a reservoir to maximize hydrocarbon recovery in a tight layer. For example, a low permeability region cannot produce hydrocarbons at the same rate as other regions. Therefore, if the other regions are shut-in, as will be explained later, all of the production wells in a given field could be temporarily converted to only low permeability wells to enhance the hydrocarbon recovery in the low permeability region. The techniques described later can be applied to a production zone that has any number of vertically arranged production regions of differing permeabilities. The techniques described later are not limited to vertical wellbores and will work for angled wellbores.

FIG. 1 shows a schematic of an example production field 100 with a subterranean zone entrapping hydrocarbons. This zone is subdivided into vertically arranged, fluidically isolated regions in the same reservoir zone. In this example, the production field 100 has a non-producing region 101, an upper layer of seal rock 102, a first production region 104, a first (low permeability) tight streak 106, a second production region 108, a second tight streak 110, and a third production region 112.

Tight streaks are sections of low permeability, but they are different from seal rock, which has almost no permeability. As a result, the various regions in field 100 are within the same production zone of the reservoir. Permeability is a measure of how easily fluid can flow through a section of rock. The higher the permeability, the easier fluid flows through the rock. Production zones do not always have a uniform permeability, and integrated production system 1000 takes advantage of that by placing packers in line with naturally occurring tight streaks. Tight streaks have a low permeability in comparison to the production regions. In example production field 100, permeability of the first production region 104 is less than the permeability of the second production region 108, and the permeability of the second production region 108 is less than a permeability of the third production region 112.

Within the production field there is a production wellbore 162 and an injection wellbore 164. The production wellbore 162 has a production well tree 131 and a production panel box 132 positioned on the uphole end of the production wellbore 162. The production well tree 131 is configured to control the flow of the well, and the production panel 132 acts as the interface for all of the sensors and controls for production wellbore 162. The injection wellbore 164 has an injection well tree 133 and an injection panel box 134 positioned on the uphole end of the injection wellbore 164. The injection well tree 164 is configured to control the flow of the well and the injection panel 134 acts as the interface for all of the sensors and controls for production wellbore 162. A production cased-hole packer 144 positioned at the top of the producing section of the wellbore 162 while the injection wellbore 164 has an injection cased hole packer 114 at the top of the injection section of the injection wellbore 164. As stated above, hydrocarbons can be produced out of production wellbore 162 while fluid (for example, gas, water, brine, or other fluid) can be injected into the formation with injection wellbore 164. The injection process helps “push” hydrocarbons towards the production wellbore 162 where they can be produced.

As permeability is variable across each production region, the effectiveness of injection is variable as well. For example, production region 112 has a high permeability, so injection may push the hydrocarbons in this region towards the production wellbore 162 at a faster rate than they would in production region 104. The effects of variable permeability are explained in greater detail later in the disclosure.

An integrated recovery system 1000 is installed in production field 100. The production wellbore 162 contains a production tubing 166 that is substantially the length of the wellbore. That is, the production wellbore 162 is long enough to reach every production region that the production wellbore 162 goes through. The production tubing 166 has a flow regulator to regulate the flow in each production region. The flow regulation can be done with a valve or by other techniques. In other words, production for each region can be turned on or off or throttled somewhere in between. In the example of FIG. 1, a first open production valve 148 is located on the production tubing 166 within the first production region 104. A second open production valve 154 is located on production tubing 166 within the second production region 108. A third open production valve 160 is located on production tubing 166 within the third production region 112. The valves in production tubing 166 can be any valve suitable for both sealing and throttling flow, such as a gate valve. The valves in production tubing 166 can be controlled through several different types of control systems, such as a hydraulic control system. The flow through the production tubing 166 is co-mingled between all regions.

Each production region within the production wellbore 162 is fluidically isolated with an open hole packer and a tight streak, that is, flow between each region is negligible; Flow only flows substantially through the regions rather than across regions. Tight streaks can have a permeability of 0.5 to 2 millidarcy while a production region can have a permeability of 20 to 150 millidarcy. In the example of FIG. 1, the first production region 104 is isolated from the second production region 108 by a first production packer 150 and the first tight streak 106. The first production packer 150 is positioned in line with the first tight streak 106 to provide proper isolation. The low permeability of the tight streaks reduces fluid flow across them to the point that production flow between regions is negligible. Each production region within the production wellbore 162 can contain a pressure sensor, a flow meter, or both. In the example of FIG. 1, a first production pressure sensor 146 can be positioned within the first production region 104 of production wellbore 162. A second production pressure sensor 152 can be positioned within the second production region 108 of production wellbore 162. A third production pressure sensor 158 can be positioned within the third production region 112 of production wellbore 162. Different types of pressure sensor can be used in wellbore 162, such as quartz pressure transducers. Each sensor is capable of transmitting information to a topside facility. The information is transmitted via a first production sensor line 126. The first production sensor line 126 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. A first flow meter 172 can be positioned within the first production region 104 of production wellbore 162. A second flow meter 174 can be positioned within the second production region 108 of production wellbore 162. A third flow meter 176 can be positioned within the third production region 112 of production wellbore 162. Different types of flowmeters can be used within wellbore 162, such as a venturi meter. Each flow meter is capable of transmitting information to a topside facility. The information can be transmitted via a second production sensor line 170 or via the first production sensor line 126. The second production sensor line 170 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three.

Any of the production sensors are capable of detecting water breakthrough. Water breakthrough can be detected by the increase in water-cut at the surface; downhole sensors, such as flow meter 172 or pressure sensor 146, can indicate which production region is producing water. Early water breakthrough may be considered more than 35% water at the surface of an oil producing well. Early water breakthrough occurs when a high oil flow rate from a high permeability production zone is displaced by injection fluid 208. High volumes of the injection fluid 208 preferentially flows through higher permeability production regions. When water breakthrough is detected, a single production region can be shut-in or multiple production regions can be shut-in. Any of the production sensors are capable of detecting cross flow. The Crossflow can happen when the production wellbore 162 is shut-in at surface. Shutting-in the production wellbore 162 at surface is required at times for maintenance or during periods of low oil demand. In some cases, crossflow is detected with a wireline flow meter survey. A wireline flowmeter survey involves running a spinner meter downhole.

A single production region can be shut-in or multiple production regions can be shut-in. A region is shut-in whenever both the production valve and the injection valve is closed within the same region. As each region is effectively isolated, the other regions can continue injection and production operations. Additionally, each region can be configured to shut-in when a well-choke is closed. Shutting-in a region is disclosed in detail later in this disclosure.

The injection wellbore 164 contains an injection tubing 168 that is substantially the length of the wellbore, that is, it is long enough to reach every production region that the injection wellbore 164 goes through. The injection tubing 168 has a flow regulator to regulate the flow in each production region. The flow regulation can be done with a valve or any other techniques. In other words, injection for each region can be turned on or off or throttled somewhere in between. In the example of FIG. 1, a first open injection valve 116 is located on the injection tubing 168 within the first production region 104. A second open injection valve 120 is located on injection tubing 168 within the second production region 108. A third open injection valve 124 is located on injection tubing 168 within the third production region 112. The valves in injection tubing 168 can be any valve suitable for both sealing and throttling flow, such as a gate valve. The valves in injection tubing 168 can be controlled through several different types of control systems, such as a hydraulic control system. The flow through the injection tubing 168 is co-mingled between all of the regions.

Each production region within the injection wellbore 164 is fluidically isolated with an open hole packer and a tight streak. In the example of FIG. 1, the first production region 104 is isolated from the second production region 108 by a first injection packer 118 and the first tight streak 106. The first injection packer 118 is positioned in line with the first tight streak 106 to provide proper isolation. The low permeability of the tight streaks reduces fluid flow across them to the point that injection flow between regions is negligible.

Each production region within the injection wellbore 164 contains a sensor that can measure pressure, flow, or both. In the example of FIG. 1, a first injection pressure sensor 138 is positioned within the first production region 104 of injection wellbore 164. A second injection pressure sensor 140 is positioned within the second production region 108 of injection wellbore 164. A third injection pressure sensor 142 is positioned within the third production region 112 of injection wellbore 164. Each sensor is capable of transmitting information in real time to a topsides facility. The information is transmitted via a first injection sensor line 136. The first injection sensing line 136 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. In some implementations, a first injection flowmeter is positioned within the first production region 104 of injection wellbore 164. A second injection flowmeter is positioned within the second production region 108 of injection wellbore 164. A third injection flowmeter is positioned within the third production region 112 of injection wellbore 164. Each flowmeter is capable of transmitting information in real time to a topsides facility. The information can be transmitted via a first injection sensor line 136, or a dedicated sensor line can be used. The first injection sensing line 136 can be made up of hydraulic tubing, electrical conductors, fiber optic cabling, or any combination of the three. Flow of injection fluid into each region can be controlled in real time based on readings from the flowmeters. Different flowmeters can be used in injection wellbore 164, such as a venture flow meter.

Each production region within the injection wellbore 164 can contain a temperature sensor, such as sensing line 130. In the example of FIG. 1, temperature sensing line 130 is a fiber optic cable capable of sensing a temperature profile across multiple production regions. The temperature sensing line 130 is capable of transmitting information to a topside facility. Flow of injection fluid into each region can be controlled based on readings from the temperature sensing line 130. For example, the temperature sensing line 130 could be used to determine a warm-back profile of the wellbore. A warm back profile is taken whenever an injection well is shut-in, and details the rate that the wellbore “warms up”. Based on the warm-up rate for each region, permeability can be determined. The warm-back profile can assist engineers in determining an ideal injection rate for each region.

As mentioned earlier, integrated production system 1000 prevents several issues that can plague open hole wellbores, such as those shown in production field 100. Such issues can include crossflow in a wellbore, early water breakthrough, as well as others. FIG. 2 shows the production field 100 of FIG. 1 without integrated recovery system 1000 installed. In this example, injection fluid 208 is pumped down the injection wellbore 164 while hydrocarbons 202 are produced from the production well 162. Injection fluid starts to travel through the various production zones once the injection wellbore 164 is pressurized. A first injection flow 210 flows through the first production region 104. A second injection flow 212 flows through the second production region 108. A third injection flow 214 flows through the third production region 112. The first injection flow 210 is substantially confined from the second injection flow by the first tight streak 106. The second injection flow 212 is substantially confined from the first injection flow 210 and the third injection flow 214 by tight streak 106 and tight streak 110 respectively. The third injection flow 214 is substantially confined from the second injection flow 212 by tight streak 110. The flow through the injection wellbore 164 is co-mingled between all of the regions. The flow through the production wellbore 162 is co-mingled between all regions as well. Co-mingling can occur because the various production regions are in the same production zone of the reservoir, so chemical reactions between the regions is unlikely to occur.

The injection flow rates in each production region are proportional to the permeability of each production region, that is, the injection flow rate can be different in each region. As mentioned earlier, the variable permeability in each region can lead to early water breakthrough 204 or crossflow 206. In FIG. 3, the example production field 100 is shown with the third production region 112 isolated from both injection tubing 168 and production tubing 166. A closed third injection valve 304 and a closed third production valve 302 isolate the production region 112 from the injection tubing 168 and production tubing 166. Both closed valves in addition to the second production packer 156, second injection packer 122, and tight streak 110 effectively isolate production region 112 from the rest of the production field 100. Such isolation prevents early water breakthrough 204 and cross flow 206.

In FIG. 4, the example production field 100 is shown with injection disabled in production zone 108 and production zone 112. A second closed injection valve 402 in addition to the first injection packer 118, the first tight streak 106, the second injection packer 122, and the second tight streak 110 isolate production region 108 from injection. A third close injection valve 304 in addition to the second injection packer 122 and the second tight streak 110 isolate production region 112 from injection. Such isolation allows injection fluid to be targeted only where it is needed, prevents early water breakthrough 204, and prevents cross flow 206.

FIG. 5 shows a flowchart for a potential method to utilize the integrated recovery system 1000 for hydrocarbon production. At 502, a production well is formed in a geologic formation. At 504, an injection well is formed in a geologic formation. At 506, vertically arranged regions are fluidically isolated from one another. The isolation occurs by lowering production tubing 166 into the production wellbore 162, and lowering injection tubing 168 into injection wellbore 164. Packers are placed around the production tubing 166 in the annulus between the outer surface of the production tubing 166 and the inner surface of the production wellbore 162. Packers are also placed around the injection tubing 168 in the annulus between the outer surface of the injection tubing 168 and the inner surface of the injection wellbore 164. Each packer is installed in line with a respective tight streak. Valves are installed on the production tubing 166 at depths that correspond with each production region. Valves are also installed on the injection tubing 168 at depths that correspond with each production region. The valves can be throttled to control the rate of injection in each production region. At 508, the flow of injection fluid is controlled into each fluidically isolated region. The fluid injection and production operations can be controlled by an operator or an automated controller. An automated controller can control valves within a wellbore or within a topside facility.

As stated previously, the techniques described here can be applied to a production zone that has any number of vertically arranged regions of differing permeabilities. The techniques disclosed before are not limited to vertical wellbores and will work for angled wellbores.

Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims. 

What is claimed is:
 1. A method comprising: in a subterranean zone entrapping hydrocarbons, the subterranean zone comprising multiple vertically arranged regions, each region having a respective permeability for fluid flow, an open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production formed in the subterranean zone through the multiple vertically arranged regions: at each of the production well and the injection well, fluidically isolating the vertically arranged regions from each other, wherein injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region; and controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
 2. The method of claim 1, wherein the multiple vertically arranged regions comprise a first region, a second region, and a third region vertically arranged in that sequence, wherein a permeability of the first region is more than a permeability of the second region and less than a permeability of the third region, wherein fluidically isolating the vertically arranged regions from each other comprises: lowering an injection tubing into the injection well, the injection tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and installing a first packer around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region, the first packer having at least a thickness of the second region.
 3. The method of claim 2, wherein controlling the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region comprises: installing a first valve in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region; and controlling the flow of the injection fluid into the first region and the third region by controlling the first valve and the second valve, respectively.
 4. The method of claim 3, further comprising: installing a first sensor in the portion of the injection tubing residing in the first region, the first sensor configured to sense a fluid parameter of the injection fluid flowed through the portion of the injection tubing, wherein the flow of the injection fluid into the first region is controlled based on the fluid parameter sensed using the first sensor.
 5. The method of claim 4, wherein the first sensor comprises a pressure sensor or a flow meter.
 6. The method of claim 2, further comprising: lowering a production tubing into the production well, the production tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and installing a second packer around the production tubing in an annulus between the production well and the subterranean zone and at a location of the second region, the second packer having at least a thickness of the second region.
 7. The method of claim 6, further comprising: installing a second sensor in the portion of the injection tubing residing in the first region, the second sensor configured to sense a temperature of the injection fluid flowed through the injection tubing, wherein the flow of the injection fluid through the first region is controlled based on the temperature sensed using the second sensor.
 8. The method of claim 6, wherein the second sensor comprises a pressure sensor or a flow meter.
 9. The method of claim 1, further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of injection fluid from the injection well into the production well.
 10. The method of claim 9, wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well comprises: detecting breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides; shutting in the production well at the surface; and shutting off injection fluid flow into the region of the subterranean zone in which the injection well resides.
 11. The method of claim 1, further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region.
 12. The method of claim 11, wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region comprises, in response to determining the cross flow from the high permeability region to the low permeability region, shutting off injection fluid flow into the high permeability region.
 13. The method of claim 11, further comprising detecting the cross flow using a sensor.
 14. A method comprising: forming a production well in a subterranean zone comprising multiple vertically arranged regions, each having a respective permeability for fluid flow, the production well extending through the multiple regions; forming an injection well in the subterranean zone to aid hydrocarbon production through the production well, the injection well extending through the multiple regions; at each of the production well and the injection well, fluidically isolating the vertically arranged regions from each other, wherein injection fluid injected through the injection well into a fluidically isolated region is substantially confined to flow in the fluidically isolated region; and controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
 15. The method of claim 14, further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of injection fluid from the injection well into the production well.
 16. The method of claim 15, wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining breakthrough of the injection fluid from the injection well into the production well comprises: detecting breakthrough of the injection fluid into a region of the subterranean zone in which the production well resides; shutting in the production well at the surface; and shutting off injection fluid flow into the region of the subterranean zone in which the injection well resides.
 17. The method of claim 14, further comprising controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region that is fluidically isolated from the high permeability region.
 18. The method of claim 17, wherein controlling the flow of the injection fluid into each fluidically isolated region based on determining cross flow from a high permeability region to a low permeability region comprises, in response to determining the cross flow from the high permeability region to the low permeability region, shutting off injection fluid flow into the high permeability region.
 19. A method comprising: in a subterranean zone entrapping hydrocarbons, the subterranean zone comprising a first region, a second region, and a third region vertically arranged in that sequence, wherein a permeability of the first region is more than a permeability of the second region and less than a permeability of the third region, an open production well to produce the hydrocarbons and an open injection well to aid hydrocarbon production formed in the subterranean zone through the three regions: at each of the production well and the injection well, fluidically isolating the first region from the third region, wherein injection fluid injected through the injection well into the first region is substantially confined to flow in the first region and not the third region, and vice versa; and controlling a flow of the injection fluid into each fluidically isolated region to control a recovery of hydrocarbons trapped in each fluidically isolated region.
 20. The method of claim 19, wherein fluidically isolating the first region from the third region comprises: lowering an injection tubing into the injection well, the injection tubing extending from a surface of the subterranean zone through the first region, the second region and the third region; and installing a first packer around the injection tubing in an annulus between the injection well and the subterranean zone and at a location of the second region, the first packer having at least a thickness of the second region, and wherein controlling the flow of the injection fluid into each fluidically isolated region to control the recovery of the hydrocarbons trapped in each fluidically isolated region comprises: installing a first valve in a portion of the injection tubing residing in the first region and a second valve in a portion of the injection tubing residing in the third region; and controlling the flow of the injection fluid into the first region and the third region by controlling the first valve and the second valve, respectively. 